Oil is frequently recovered from subterranean reservoirs by use of flooding processes wherein a displacing fluid, such as water or gas, is injected into injection wells to drive the oil toward production wells where it is withdrawn. The mobility of fluid flowing through porous media in the subterranean formations found in such reservoirs may be defined as the ratio of relative permeability to fluid viscosity for that fluid (relative permeability/fluid viscosity). For some flooding processes, the mobility of the in-situ oil being displaced is significantly lower than that of the displacing fluid, and adverse mobility ratio causes the injected displacing fluid to finger through the oil, resulting in much of the oil being stranded and unrecovered. Hence, it is desirable that for an efficient flooding process, the injected fluid should have a composition and viscosity that maintains a lower mobility for the displacing fluid than the mobility of the oil being displaced. The mobility ratio for the flooding process is the ratio of the mobility of the displacing fluid to the mobility of the oil being displaced (mobility of displacing fluid/mobility of oil). A favorable mobility ratio, generally considered to be a mobility ratio of 1.0 or lower, provides improved displacement efficiency.
Some flooding processes utilize foams as a displacing fluid. For example, U.S. Pat. No. 6,105,672 (to Deruyter et al.) discloses an enhanced (WAG type) oil recovery process in an underground reservoir that uses forced injection, through one or more wells, alternately of fluid slugs and gas slugs, and recovery, through one or more production wells, of petroleum fluids displaced by the wetting fluid and the gas injected. The process is said to include dissolving a pressurized gas in the liquid of certain slugs and, after injection, relieving the pressure prevailing in the reservoir so as to generate gas bubbles by nucleation in the smallest pores, which is said to have the effect of driving the oil away from the less permeable zones into the more permeable zones (with large pores or with fractures) where the oil is swept by the gas slugs injected later on. Implementation of the process is said to considerably increase the oil recovery ratio that is usually reached with WAG type processes. According to one embodiment, at least one of the wetting liquid slugs injected during the injection stage comprises water to which foaming agents or surfactants have been added so that the pressure decrease in the reservoir generates the in-situ formation of foams.
Various other flooding processes have utilized emulsions as the displacing fluid to provide favorable mobility control and effective displacement of crude oil within the reservoir. For example, U.S. Pat. Nos. 5,855,243, 5,910,467, 5,927,404, and 6,068,054 (all to Bragg) disclose the use of solids-stabilized emulsions that provide stable and favorable mobility control for displacing crude oil. In one possible application, the emulsion comprises oil and water plus dissolved gas to reduce viscosity and is stabilized using undissolved solid particles which are at least partially oleophilic. Foams are also disclosed as special cases of emulsions, containing very high gas contents, with internal gas bubbles stabilized by interfacial films containing water, hydrocarbons, or other liquids, and stabilized by surfactants or other emulsifying agents. Noting that surfactants are often used to create stable films for creating foams, it is disclosed that stable films are to be created by mixtures of oil, water, and fine solid particles, where the solid particles interacting with the oil and water stabilize the foam film. Additions of gas to the emulsion mixture at the time that the oil, water, and solids are blended, mixed, and sheared are disclosed to permit generation of either an emulsion comprising primarily liquids with a lesser fraction of gas, or a foam comprising primarily gas, with only sufficient liquids to form a stable foam, depending on the desired properties of the final mixture. A disclosed example is when the density of a water-in-oil emulsion without included gas might be significantly greater than the density of oil to be displaced within the formation. If said emulsion without gas is injected to displace oil, it is noted that gravity underride of the oil may occur because the emulsion would tend to sink below the oil to lower portions of the formation. However, it is disclosed that sufficient gas can be included in the emulsion to cause the emulsion density under formation conditions to equal the density of the oil being displaced, thus avoiding gravity underride. Other applications of such gas-containing emulsions or foams stabilized by fine solids described in the aforementioned patents are inclusion of gas to reduce the viscosity of the injected emulsion, or inclusion of compressible gas to store energy for release as the emulsion encounters lower-pressure zones within the formation.
United States Patent Application Publication US 2003/0220204 (to Baran, Jr.) discloses the use of surface-modified nanoparticles in fluids used to recover hydrocarbon from underground formations. The use of surface-modified nanoparticles in such fluids is said to provide foams that are stable under pressure yet have a shorter foam lifetime than typical surfactant-stabilized foams after the pressure is released or lowered.
As previously noted, methods for making and using solids-stabilized oil-external emulsions for producing hydrocarbons from subterranean oil reservoirs have previously been disclosed. (See, e.g., U.S. Pat. Nos. 5,855,243, 5,910,467, and 6,068,054.) Such solids-stabilized emulsions can be used for displacing oil and maintaining mobility control during the flooding process. The overall net oil recovery resulting from the flooding process can be increased if the injected emulsions contained less oil, as would be the case if additions of gas to the emulsions were made to generate foam. In such cases, it is desirable to control the bubble size and bubble size distribution in the foam. In particular, it is desirable to maintain the average bubble size in the foam below a certain level, and also to maintain a bubble size distribution that is as uniform as possible. Accordingly, there is a need for improved methods of generating such foams while controlling bubble size and distribution. There is also a need for improved methods of producing hydrocarbons from a subterranean formation utilizing such foams.